The invention relates to a method for interpreting data acquired in a hydrocarbon well in production.
More precisely, the method of the invention is designed to ensure that the data collected in the well during production are correctly interpreted in order to know precisely the flow conditions, namely the relative volumetric flow-rates, inside the well.
To ensure the monitoring and diagnostic functions in hydrocarbon wells in production, a certain amount of data, mainly physical data, has to be acquired. The data essentially relate to the multiphase fluid that flows in the well (flow rate, proportions of its various phases, temperature, pressure, etc.). They can also relate to certain characteristics of the well itself (ovalization, inclination). These data will, for example, permit to quantitatively identify, at all depths, fluid entry zones and fluid exit zones in order to be able to re-plug or re-perforate the corresponding zones when needed. This monitoring will thus permit to minimize surface production of undesired fluids like water and maximize the production of valuable fluids like oil.
To acquire said data, as shown in particular by document FR-A-2 732 068, a conventional solution consists in taking, firstly, an overall measurement of the speed of the fluid flowing in the well, by means of a spinner placed in the axis of the well, and secondly, measurements (that might be local) enabling the proportions of the various phases of the fluid in certain regions of the well to be determined. The speed measurement and the hold-up measurements are taken at various depths. The hold-up measurements are taken by means of various sensors that can be resistivity sensors, optical sensors, etc.
To determine the flow rate of the various phases of the fluid flowing in the well, the flow rate of the fluid over the section of the well is calculated from the measurements taken by said existing apparatus by multiplying the overall speed measurement (consisting in the measured speed at the center of the well multiplied by a coefficient typically between 0.6 and 1) by the section of the well at the place where the measurement is taken. The proportion relating to the phase under consideration as determined by the sensor is then applied to said overall flow rate.
However, it is known that the distribution of the various phases of the fluid flowing in an oil well varies depending on whether the well is vertical, inclined or horizontal. Because of the difference in density of the various phases of the fluid, said phases become progressively more stratified with increasing inclination of the well. Thus, in the case of a three-phase fluid containing water, oil and gas, the three phases tend to flow one on top of the other when the well is horizontal or greatly inclined. Consequently, the distribution of the phases in the well (hold-up of the phases) and the speed of each phase are not uniform over the section of said well: a sharper description of these functions over the well cross-section is needed to calculate the flow rate of each phase.
This description will be achieved with sensors (for example local probes and mini-spinners) located on various known points of the cross section of the well as stated in the document WO 01/11190. This document is based on the observation that the flow rate of any one phase of the fluid is not equal to the product of the overall (average) speed of the fluid multiplied by the section of the well and by the volumetric fraction of said phase in the flowing fluid, but is rather the product of the average speed of the phase under consideration multiplied by the section and by the volumetric fraction of said phase.
The interpretation of these data, collected at each local spinner and probe in order to calculate relative volumetric flow rates at all depths, is thus becoming a very important procedure in order to estimate precisely the behavior of each fluid constituting the well effluent. This interpretation actually requires interpolation of the values on the basis of a flow model applied to the effluent flow, said model varying depending on the current flow conditions.